Drilling Dynamics Data Recorder

ABSTRACT

A drilling dynamics data recorder is positioned within a slot in a downhole tool. The drilling dynamics data recorder may include a sensor package, the sensor package including one or more drilling dynamics sensors and a processor, the processor in data communication with the one or more drilling dynamics sensors. The drilling dynamics data recorder may also include a memory module, the memory module in data communication with the one or more drilling dynamics sensors and a communication port, the communication port in data communication with the memory module. The drilling dynamics data recorder may further include an electrical energy source, the electrical energy source in electrical communication with the memory module, the one or more drilling dynamics sensors, and the processor.

CROSS REFERENCE TO RELATED APPLICATIONS

This application is a continuation of U.S. non-provisional Ser. No.15/677,244 filed Aug. 15, 2017, which claims priority from U.S.provisional application No. 62/375,302, filed Aug. 15, 2016, and fromU.S. provisional application No. 62/411,421, filed Oct. 21, 2016, eachof which are incorporated herein by reference.

TECHNICAL FIELD/FIELD OF THE DISCLOSURE

The present disclosure relates generally to downhole drilling tools, andspecifically to drilling dynamics data recorders for downhole tools.

BACKGROUND OF THE DISCLOSURE

Wellbores are traditionally formed by rotating a drill bit positioned atthe end of a bottom hole assembly (BHA). The drill bit may be actuatedby rotating the drill pipe, by use of a mud motor, or a combinationthereof. As used herein, the BHA includes the drill bit. Conventionally,BHAs may contain only a limited number of sensors and have limited dataprocessing capability. The operating life of the drill bit, mud motor,bearing assembly, and other elements of the BHA may depend uponoperational parameters of these elements, and the downhole conditions,including, but not limited to rock type, pressure, temperature,differential pressure across the mud motor, rotational speed, torque,vibration, drilling fluid flow rate, force on the drill bit or theweight-on-bit (“WOB”), inclination, total gravity field, gravitytoolface, revolutions per minute (RPM), radial acceleration, tangentialacceleration, relative rotation speed and the condition of the radialand axial bearings. The combination of the operational parameters of theBHA and downhole conditions are referred to herein as “drillingdynamics.”

To supplement conventional BHA sensors, drilling dynamics data may bemeasured by drilling dynamics sensors. Measurement of these aspects ofelements of the BHA may provide operators with information regardingperformance and may indicate need for maintenance. Conventional downholedrilling dynamics sensors are located on a dedicated sub used to housethe sensors. The conventional downhole drilling dynamics sensor sub ismechanically coupled to a portion of the drill string or the desireddownhole drilling equipment, directly or indirectly.

SUMMARY

The present disclosure provides for a drilling dynamics data recorderpositioned within a slot in a downhole tool. The drilling dynamics datarecorder includes a sensor package, the sensor package including one ormore drilling dynamics sensors and a processor, the processor in datacommunication with the one or more drilling dynamics sensors. Thedrilling dynamics data recorder also includes a memory module, thememory module in data communication with the one or more drillingdynamics sensors and a communication port, the communication port indata communication with the memory module. The drilling dynamics datarecorder further includes an electrical energy source, the electricalenergy source in electrical communication with the memory module, theone or more drilling dynamics sensors, and the processor.

In addition, the present disclosure provides for a drilling dynamicsdata recorder system. The drilling dynamics data recorder systemincludes a drilling dynamics data recorder. The drilling dynamics datarecorder includes a sensor package, the sensor package including one ormore drilling dynamics sensors. The drilling dynamics data recorder alsoincludes a memory module, the memory module in data communication withthe sensor package and a communication port, the communication port indata communication with the memory module. The drilling dynamics datarecorder further includes a processor, the processor in datacommunication with the drilling dynamics sensor, and an electricalenergy source, the electrical energy source in electrical communicationwith the memory module, the sensor package, and the processor. Thedrilling dynamics data recorder system also includes a downhole tool,the drilling dynamics data recorder within the downhole tool.

The present disclosure also provides for a method. The method includesproviding a drilling dynamics data recorder, the drilling dynamics datarecorder positioned within a downhole tool. The drilling dynamics datarecorder includes a sensor package, the sensor package having one ormore drilling dynamics sensors. The drilling dynamics data recorder alsoincludes a memory module, the memory module in data communication withthe sensor package and a communication port, the communication port indata communication with the memory module. The drilling dynamics datarecorder further includes a processor, the processor in datacommunication with the one or more drilling dynamics sensors, and anelectrical energy source, the electrical energy source in electricalcommunication with the memory module, the sensor package, and theprocessor. The method also includes positioning the downhole tool withina wellbore, taking measurements using the drilling dynamics sensors, andtransmitting the measurements from the drilling dynamics sensors to thememory module. The method further includes memory logging themeasurements from the one or more drilling dynamics sensors in thememory module to form drilling dynamics data.

The present disclosure also provides for a downhole tool having abearing assembly. The bearing assembly may include an upper bearinghousing. The upper bearing housing may include an upper bearing housingouter surface. The upper bearing housing outer surface may be generallycylindrical along a bearing housing longitudinal axis. The upper bearinghousing may include an upper bearing housing bore formed thereindefining an upper bearing housing inner surface. The upper bearinghousing bore may be generally cylindrical and may be formed along a borelongitudinal axis. The bore longitudinal axis may be formed at an angleto the bearing housing longitudinal axis. The bearing assembly mayinclude a lower bearing housing. The lower bearing housing may bemechanically coupled to the upper bearing housing. The lower bearinghousing may include a lower bearing housing bore formed along the borelongitudinal axis defining a lower bearing housing inner surface. Thebearing assembly may include a driveshaft positioned within andconcentric with the upper bearing housing bore and the lower bearinghousing bore such that it extends along the bore longitudinal axis. Thedownhole tool may also include a first drilling dynamics data recorderpositioned within a slot in the upper bearing housing. The drillingdynamics data recorder includes a sensor package, the sensor packageincluding one or more drilling dynamics sensors and a processor, theprocessor in data communication with the one or more drilling dynamicssensors. The drilling dynamics data recorder also includes a memorymodule, the memory module in data communication with the one or moredrilling dynamics sensors and a communication port, the communicationport in data communication with the memory module. The drilling dynamicsdata recorder further includes an electrical energy source, theelectrical energy source in electrical communication with the memorymodule, the one or more drilling dynamics sensors, and the processor.

The present disclosure also provides for a downhole tool. The downholetool may include a housing rotatably coupled to and positioned about amandrel. The downhole tool may include a steering blade positioned onthe housing. The steering blade may be extendable by an extension forceto contact a wellbore, the extension force caused by a differentialpressure between a steering cylinder and a pressure in a surroundingwellbore. The differential pressure may be caused by fluid pressure of afluid within the steering cylinder. The steering cylinder may bepositioned within the housing. The steering blade may be at leastpartially positioned within the steering cylinder. The steering cylinderfluidly coupled to a steering port. The downhole tool may include anadjustable orifice. The adjustable orifice may be fluidly coupledbetween the interior of the mandrel and the steering cylinder. Theadjustable orifice may be adjustable between an open position and atleast one of a partially open position and a closed position. Thedownhole tool further includes a bit box, the bit box coupled to themandrel and an upper mandrel, the upper mandrel coupled to the mandrel.The downhole tool also includes one or more drilling dynamics datarecorders, each of the drilling dynamics data recorders positionedwithin a slot in the downhole tool.

BRIEF DESCRIPTION OF THE DRAWINGS

The present disclosure is best understood from the following detaileddescription when read with the accompanying figures. It is emphasizedthat, in accordance with the standard practice in the industry, variousfeatures are not drawn to scale. In fact, the dimensions of the variousfeatures may be arbitrarily increased or reduced for clarity ofdiscussion.

FIG. 1 depicts a cross section of a drilling dynamics data recorderconsistent with at least one embodiment of the present disclosure.

FIG. 1A depicts the drilling dynamics data recorder of FIG. 1 within adownhole tool consistent with at least one embodiment of the presentdisclosure.

FIG. 1B is a photograph of the drilling dynamics data recorder of FIG. 1.

FIG. 1C is a partial cross-section of a drilling dynamics data recorderand hatch cover consistent with at least one embodiment of the presentdisclosure.

FIG. 2 depicts a cross section of a drilling dynamics data recorderconsistent with at least one embodiment of the present disclosure.

FIG. 2A depicts the drilling dynamics data recorder of FIG. 2 within adownhole tool consistent with at least one embodiment of the presentdisclosure.

FIG. 2B is depicts the drilling dynamics data recorder of FIG. 2 .

FIG. 2C is a side view of a motor mandrel including a drilling dynamicsdata recorder consistent with at least one embodiment of the presentdisclosure.

FIG. 2D is a side view of a motor mandrel including a drilling dynamicsdata recorder consistent with at least one embodiment of the presentdisclosure.

FIG. 3 depicts a drilling dynamics data recorder within a carrier subconsistent with at least one embodiment of the present disclosure.

FIG. 4 depicts drilling dynamics data recorders within a mud motorconsistent with at least one embodiment of the present disclosure.

FIG. 4A depicts a transmission of a mud motor consistent with at leastone embodiment of the present disclosure.

FIG. 5 depicts drilling dynamics data recorders within a mud motorconsistent with at least one embodiment of the present disclosure.

FIG. 5A depicts a drilling dynamics data recorder consistent withcertain embodiments of the present disclosure.

FIG. 5B depicts a drilling dynamics data recorder consistent withcertain embodiments of the present disclosure

FIG. 6 depicts a drilling dynamics data recorder within a frictionreduction tool consistent with at least one embodiment of the presentdisclosure.

FIG. 6A depicts a drilling dynamics data recorder within the frictionreduction tool of FIG. 6 consistent with at least one embodiment of thepresent disclosure.

FIG. 7 depicts drilling dynamics data recorders within a frictionreduction tool and carrier subs consistent with at least one embodimentof the present disclosure.

FIGS. 8A-8D depict slots for drilling dynamics data recorders withindifferent portions of a drill bit consistent with embodiments of thepresent disclosure.

FIG. 9 depicts slots for drilling dynamics data recorders within a drillbit shank consistent with embodiments of the present disclosure.

FIGS. 10A and 10B depict drilling dynamics data recorders in stabilizersconsistent with certain embodiments of the present disclosure.

FIG. 11 depicts a ball seat assembly having a drilling dynamics datarecorder consistent with certain embodiments of the present disclosure.

FIG. 12 depicts a stick-slip mitigation tool having a drilling dynamicsdata recorder consistent with certain embodiments of the presentdisclosure.

FIG. 13 depicts a turbine having a drilling dynamics data recorderconsistent with certain embodiments of the present disclosure.

FIG. 14 is a block diagram of a drilling dynamics data recorderconsistent with at least one embodiment of the present disclosure.

FIG. 15 is a block diagram of a drilling dynamics data recorderconsistent with at least one embodiment of the present disclosure.

FIG. 16 depicts a steering tool having a drilling dynamics data recorderconsistent with certain embodiments of the present disclosure.

FIG. 17 is an elevation view of a bearing assembly consistent with atleast one embodiment of the present disclosure.

FIG. 18 is a cross section view of the bearing assembly of FIG. 17 .

FIG. 19 depicts an elevation view of a bottom hole assembly (BHA)consistent with at least one embodiment of the present disclosure.

FIG. 20 depicts a cross section view of the BHA of FIG. 19 .

FIG. 21 depicts a downhole tool having a bearing assembly consistentwith at least one embodiment of the present disclosure.

FIG. 22 depicts a schematic view of a downhole tool in partial crosssection consistent with at least one embodiment of the presentdisclosure.

FIGS. 23A, 23B depict schematic cross sections of the downhole tool ofFIG. 22 in a centralizing position.

FIGS. 24A, 24B depict schematic cross sections of the downhole tool ofFIG. 22 in a steering position.

FIG. 25 depicts a cross section view of a diverter of a downhole toolconsistent with at least one embodiment of the present disclosure.

FIG. 26A depicts a partial cross section view of a downhole toolconsistent with at least one embodiment of the present disclosure.

FIG. 26B depicts a detail view of the downhole tool of FIG. 26A in anopen position.

FIG. 26C depicts a detail view of the downhole tool of FIG. 26A in apartially open position.

FIG. 27A depicts a partial cross section view of a downhole toolconsistent with at least one embodiment of the present disclosure.

FIG. 27B depicts a detail view of the downhole tool of FIG. 27A.

FIG. 27C depicts a perspective view of components of the downhole toolof FIG. 27A.

FIGS. 28A-28J depict a semitransparent view of a ring valve consistentwith at least one embodiment of the present disclosure in variouspositions.

FIG. 29 depicts a cross section of a downhole tool consistent with atleast one embodiment of the present disclosure.

FIG. 30 depicts a cross section of a downhole tool consistent with atleast one embodiment of the present disclosure.

FIGS. 31A-D depict schematic cross sections of a downhole toolconsistent with at least one embodiment of the present disclosure invarious rotational positions.

FIG. 32 depicts a semitransparent view of a ring valve consistent withat least one embodiment of the present disclosure.

FIG. 33 depicts a semitransparent view of a ring valve consistent withat least one embodiment of the present disclosure.

FIG. 34 depicts a semitransparent view of a ring valve consistent withat least one embodiment of the present disclosure.

FIG. 35 depicts a semitransparent view of a ring valve consistent withat least one embodiment of the present disclosure.

FIG. 36 depicts a partial cross section view of a downhole toolconsistent with at least one embodiment of the present disclosure.

FIG. 37 depicts an overall view of a downhole tool consistent with atleast one embodiment of the present disclosure.

DETAILED DESCRIPTION

It is to be understood that the following disclosure provides manydifferent embodiments, or examples, for implementing different featuresof various embodiments. Specific examples of components and arrangementsare described below to simplify the present disclosure. These are, ofcourse, merely examples and are not intended to be limiting. Inaddition, the present disclosure may repeat reference numerals and/orletters in the various examples. This repetition is for the purpose ofsimplicity and clarity and does not in itself dictate a relationshipbetween the various embodiments and/or configurations discussed.

FIG. 1 depicts an embodiment of drilling dynamics data recorder 100consistent with at least one embodiment of the present disclosure. Theembodiment of drilling dynamics data recorder shown in FIG. 1 is a“pressure barrel” design. Drilling dynamics data recorder 100 includessensor package 110. Sensor package 110 may include drilling dynamicssensors including, but not limited to, low-g accelerometers fordetermination of inclination, total gravity field, radial acceleration,tangential acceleration, and/or low-g vibration sensing; and/or gravitytoolface; high-g accelerometers for shock sensing; temperature sensors;three-axis gyroscopes for rotation speed (angular velocity) computation;Hall-effect sensors to measure relative rotation speed, along with amagnetic marker[s]; one or more strain gauges to measure one or more oftension, compression, torque on bit, weight on bit, bending moment,bending toolface, and pressure; and magnetometers for rotation speed(angular velocity) computation. Sensor package 110 may include any orall of drilling dynamics sensors listed and may include other drillingdynamics sensors not listed. Sensor package 110 may include redundantsensors, for example and without limitation, two 3-axis low-gaccelerometers and/or two 3-axis gyro sensors. Redundant sensors mayimprove reliability and accuracy. Further, the drilling dynamics sensorsmay be used for determination of other drilling dynamics data other thanthat listed. In certain embodiments, the drilling dynamics sensors aredigital, solid-state sensors. The digital, solid-state sensors maycreate less noise, have a smaller footprint, have lower mass, be moreshock-resistant, be more reliable and have better power management thananalog sensors. In certain embodiments, the accelerometers may bethree-axis accelerometers. The three-axis accelerometers may be digitalor analog sensors, including, but not limited to quartz accelerometers.In some embodiments, the gyroscopes may be three-axis gyroscopes.

As used herein, low-g accelerometers may measure up to between +/−16 G.As used herein, high-g accelerometers may measure up to between +/−200G. Rotation speed in RPM (revolutions per minute) may be measured, forexample, between 0 and 500 RPM. Temperature may be measured, forexample, between −40° C. and 175° C., between −40° C. and 150° C. orbetween −40° C. and 125° C. As further described herein below, themeasurement range of the sensors may be programmable while drillingdynamics data recorder 100 is within the wellbore. For example, thelow-g accelerometers measurement range may be changed from +/−4 G to+/−16 G while drilling.

With further attention to FIG. 1 , drilling dynamics data recorder 100may include memory module 115 in data communication with sensor package110. Memory module 115 is adapted to store data gathered by the sensorsin sensor package 110. Memory module 115 is in data communication withcommunication port 120. Communication port 120 is adapted to provide adata communications link between memory module 115 and a surfaceprocessor. Communication port 120 may be adapted to communicate withother processors in a communication bus (e.g. MWD tool) via a commoncommunication bus, for example, transmitting drilling dynamics data,statistics based on drilling dynamics data, rock mechanics information,or a combination thereof to surface via MWD.

Also depicted in FIG. 1 is processor 105. Processor 105 may be in datacommunication with the sensors in sensor package 110 and memory module115. Processor 105 may control the operation of the sensors in sensorpackage 110, as described herein below. Processor 105 may includeapplication software/firmware stored on a computer readable media, suchas program Flash memory, which is part of Processor 105. Onenon-limiting example of processor 105 with program Flash memory is a16-bit microcontroller, Model SM470R1B1M-HT from Texas Instruments(Dallas, Tex., USA). The application software/firmware may includeinstructions, for example and without limitation, for executingdeep-sleep mode, standby mode, and active mode, as described hereinbelow. The application software/firmware in processor 105 may be loadedand replaced, via communication port bus 176 through communication port120, by a surface processor. Drilling dynamics data recorder 100 mayfurther include a real-time clock, an oscillator, a fuse, and a voltageregulator. Processor 105 includes, but is not limited to amicrocontroller, microprocessor, DSP (digital signal processor), DSPcontroller, DSP processor, FPGA (Field-Programmable Gate Array) orcombinations thereof.

Memory module 115, processor 105, and sensor package 110 and/or thesensors in sensor package 110 may be in electrical communication withelectrical energy source 130. Electrical energy source 130 providespower to processor 105, memory module 115, and the sensors in sensorpackage 110. In some non-limiting embodiments, electrical energy source130 may be a lithium battery. In yet other embodiments, electricalenergy source 130 may be electrically connected to sensors in sensorpackage 110 indirectly through a voltage regulator. In otherembodiments, electrical energy source 130 may be positioned in a packageseparate from sensor package 110. In certain embodiments, electricalenergy source 130 is a battery, such as a rechargeable battery or anon-rechargeable battery. In other embodiments, electrical energy source130 may be a rechargeable or non-rechargeable battery with an energyharvesting device. The energy harvesting device may be a piezo-electricenergy harvester or a MEMS energy harvester.

As depicted in FIG. 1 , processor 105, sensor package 110, memory module115, communication port 120, and electrical energy source 130 may behoused within pressure barrel 140. In the embodiment depicted in FIG. 1, pressure barrel 140 is cylindrical or generally cylindrical. In otherembodiments, pressure barrel 140 may be of other shapes adapted tocontain processor 105, sensor package 110, memory module 115,communication port 120, and electrical energy source 130. In someembodiments, the pressure within pressure barrel 140 is atmospheric ornear-atmospheric pressure. In some embodiments, the pressure rating forpressure barrel 140 may be at least 15,000 psi. In some embodiments, thedownhole battery life of electrical energy source 130 may be at least240 hours (or 10 days), and in some embodiments, memory module 115 mayhave at least 16 M Bytes of storage. In some embodiments, memory module115 may have up to 4 G Bytes of storage.

As further shown in FIG. 1 , end caps 125, 135 may be fitted to the endsof pressure barrel 140. In certain embodiments, communication port 120may protrude through memory dump end cap 125.

FIG. 1A depicts drilling dynamics data recorder 100 within downhole tool300 in one embodiment of the present disclosure. Downhole tool 300 maybe any component of a drill or tool string within a wellbore, and mayinclude, for example and without limitation, a component of a BHA, drillbit, stabilizer, cross-over, drill pipe, drill collar, pin-boxconnection, jar, reamer, underreamer, friction reducing tool, stringstabilizer, near-bit stabilizer, mud motor, turbine, stick-slipmitigation tool, or bearing housing. As shown in FIG. 1A, drillingdynamics data recorder may be placed behind hatch cover 310 in slot 315in downhole tool 300. Slot 315 may be machined or drilled, for example,into outside surface 330 of downhole tool 300. FIG. 1B depicts therelative size of drilling dynamics data recorder 100 consistent withcertain embodiments of the present disclosure. The size of drillingdynamics data recorder 100 depicted in FIG. 1B is not limiting and maybe of any size consistent with usage in downhole tool 300. In someembodiments, as depicted in FIG. 1C, drilling dynamics data recorder 100may include location pin 145. Location pin 145 may engage with locatorslot 145′ of hatch cover 310.

FIG. 2 depicts drilling dynamics data recorder 200 consistent withcertain embodiments of the present disclosure. The embodiment ofdrilling dynamics data recorder 200 shown in FIG. 2 is a “hockey-puck”design. Drilling dynamics data recorder 200 includes communication port120 and electrical energy source 130. Drilling dynamics data recorder200 also includes data/sensor module 150. Data/sensor module 150 mayinclude a processor, sensor package containing sensors, and memorymodule, as those elements are described above with respect to drillingdynamics data recorder 100. Data/sensor module 150 may be in datacommunication with communication port 120.

The hockey-puck design of drilling dynamics data recorder 200 depictedin FIG. 2 may include disk 155. In some embodiments, disk 155 mayinclude recorder cap 160 and recorder carrier 165. In certainembodiments, communication port 120 may be positioned within disk 155,accessible by removing recorder cap 160 from recorder carrier 165. Insome embodiments, drilling dynamics data recorder 200 may includelocation pin 145 formed as part of or mechanically coupled to recordercarrier 165. In some embodiments, communication port 120 may bepositioned proximate to or within location pin 145. FIG. 2A depicts anon-limiting embodiment of the present disclosure drilling dynamics datarecorder 200 within bit sub 302 of, for example and without limitation,a motor mandrel. As depicted in FIGS. 2C, 2D, bit sub 302 may bemechanically coupled to motor mandrel 305. Motor mandrel 305 may includepin-down lower coupler 307 a as depicted in FIG. 2C, or may includebox-down lower coupler 307 b as depicted in FIG. 2D. In certainembodiments, drilling dynamics data recorder 200 may be positionedwithin screw housing 230. Screw housing may include screw housingthreads for threadedly connecting to threaded slot 240, as shown in FIG.2A. The hockey puck design of drilling dynamics data recorder 200 may beused, for example and without limitation, in areas with limited spacesuch as a motor mandrel bit box, turbine mandrel, a steerable tool bitbox, a vertical drilling tool bit box, a steerable tool upper mandrel, avertical drilling tool upper mandrel, stabilizer, ball seat or a shankof a drill bit. In some embodiments, drilling dynamics data recorder 100or 200 may be used in any of these tools.

FIG. 2B depicts the relative size of drilling dynamics data recorder 200consistent with certain embodiments of the present disclosure. The sizeof drilling dynamics data recorder 200 depicted in FIG. 2B is notlimiting and may be of any size consistent with usage in downhole tool300.

In certain embodiments, drilling dynamics data recorder 100 and drillingdynamics data recorder 200 are self-contained in that while recordingdata, no power is supplied from outside drilling dynamics data recorder100 or drilling dynamics data recorder 200, respectively. In otherembodiments, electrical power may be supplied from outside drillingdynamics data recorder 100 and 200, such as from a self-contained,separate electrical power module, for example, batteries.

FIG. 14 depicts a block diagram of drilling dynamics data recorder 100,200. Drilling dynamics data recorder includes sensor package 110 whichincludes one or more sensors. In the embodiment shown in FIG. 14 , thesensors include low-g accelerometer 111, high-g accelerometer 112,gyroscope 113, and temperature sensor 114. In some embodiments, such asthe embodiment shown in FIG. 14 , the sensors also include magnetometer116 and pressure sensor 117. In other embodiments, sensor package 110may include any of sensors 111, 112, 113, 114, 116, and 117. Sensors111, 112, 113, 114, 116, and 117 may be in data communication withprocessor 105 through sensor communication bus 170. Sensor communicationbus 170 may be a digital communication bus, such as an SPI (SerialPeripheral Interface) bus or an I²C (Inter-Integrated Circuit) bus.

In certain embodiments, Hall-effect sensor 118 is in data communicationwith processor 105 through Hall-effect sensor bus 172. Hall-effectsensor bus 172 may be a digital communication bus, such as an SPI or anI²C bus. In some embodiments, Hall-effect sensor 118 is directlyconnected to processor 105 via an input port, for example, an interruptpin or an analog-to-digital-converter pin. In other embodiments,Hall-effect sensor 118 may be a digital Hall-effect sensor or analog(ratio-metric) Hall-effect sensor. In other embodiments, Hall-effectsensor 118 may be omitted.

In the embodiment depicted in FIG. 14 , memory module 115 is in datacommunication with processor 105 through memory communication bus 174.Memory communication bus 174 may be a CAN (Controller Area Network) bus,an SPI or an I²C bus in certain non-limiting examples. Thus, sensors111, 112, 113, 114, 116, and 117 are in data communication with memorymodule 115 through sensor communication bus 170, processor 105, andmemory communication bus 174. Hall-effect sensor 118 is in datacommunication with memory module 115 through Hall-effect sensor bus 172,processor 105 and memory communication bus 174. Memory module 115 maycontain multiple memory devices, such as between 2 and 8 memory devicesor 4 memory devices. Memory device may preferably be non-volatile, suchas Flash or EEPROM (Electrically Erasable Programmable Read-Only Memory)device. One non-limiting example of EEPROM device is a 1-kbit SPIEEPROM, Model 25LC010A from Microchip (Chandler, Ariz., USA).

As further shown in FIG. 14 , processor 105 is in data communicationwith communication port 120 through communication port bus 176.Communication port bus may be a digital communication bus, including,but not limited to, a SCI (Serial Communication Interface) bus, a UART(Universal Asynchronous Receiver/Transmitter) bus, a CAN bus, a SPI busor a I²C bus. Communication port 120 may be in data communication withmemory module 115 through memory communication bus 174, processor 105,and communication port bus 176. One non-limiting example of processor105 with such communication bus feature is a 16-bit microcontroller,Model SM470R1B1M-HT from Texas Instruments (Dallas, Tex., USA).

FIG. 15 depicts another embodiment of a block diagram of drillingdynamics data recorder 100, 200. In FIG. 15 , sensor communication bus170 and memory communication bus 174 are connected to form sensor-memorybus 175.

In the embodiments shown in FIGS. 14 and 15 , electrical energy source130 is in electrical connection with each of sensors 111, 112, 113, 114,116, 117, processor 105, and memory module 115. In some embodiments,electrical energy source 130 may be electrically connected to each ofsensors 111, 112, 113, 114, 116, 117 directly. In other embodiments,electrical energy source 130 may be electrically connected to each ofsensors 111, 112, 113, 114, 116, 117 indirectly through a connection tosensor package 110. In yet other embodiments, electrical energy source130 may be electrically connected to each of sensors 111, 112, 113, 114,116, 117 indirectly through a voltage regulator.

FIG. 3 depicts drilling dynamics data recorder 100 within carrier sub320 consistent with at least one embodiment of the present disclosure.In other embodiments, drilling dynamics data recorder 200 may bepositioned within carrier sub 320. Carrier sub 320 may be inserted intoa drill string, for examples and without limitation, between two jointsof a drill string. In some embodiments, carrier sub 320 may be a bitsub. In some embodiments, carrier sub 320 may include male threadedconnection 322 and female threaded connection 324 for threaded insertioninto the drill string. Although not depicted, in other embodiments,carrier sub 320 may include two female threaded connections or two malethreaded connections.

Drilling dynamics data recorder 100, 200 may be used with a variety ofdownhole tools of which bit sub 302 is a part. In one non-limitingexample, drilling dynamics data recorder 100 may be used with mud motor400, as shown in FIG. 4 . Mud motor 400 may include rotor catch 410within a top sub, transmission 430 and bit box 450. As shown in FIG. 4 ,rotor catch recorder 425 may be positioned within rotor catch slot 420,located, for instance, proximate rotor catch 410, and bit box recorder465 may be positioned in bit box slot 460, located proximate bit box450. In certain embodiments, such as shown in FIG. 4 , transmissionrecorder 445 may be positioned within transmission slot 440 locatedproximate transmission 430. Although depicted at an upper end oftransmission 430, transmission slot 440 and transmission recorder 445may be positioned at any position within transmission 430, including,for example and without limitation, at a lower end of transmission 430as depicted in FIG. 4A. Rotor catch recorder 425, bit box recorder 465and transmission recorder 445 may include sensors for measuring lateraland axial shock and vibration, string and drill bit RPM, toolface,inclination, total gravity field, temperature, radial acceleration,tangential acceleration, and combinations thereof, for example.

FIG. 5 depicts another embodiment of the use of drilling dynamics datarecorder 100, 200 in conjunction with mud motor 400 (shown in FIGS. 5Aand 5B, respectively). In the embodiment depicted in FIG. 5 , drillingdynamics data recorder 100 may be used for top sub recorder 485positioned in top sub 480 and drilling dynamics data recorder 200 may beused for bit box recorder 465, positioned in bit box threaded slot 462.

In another embodiment, drilling dynamics data recorder 100, 200 may beused in conjunction with a friction reduction tool. Non-limitingexamples of friction reduction tools may be found in U.S. Pat. No.6,585,043 entitled “Friction Reducing Tool” and U.S. Pat. No. 7,025,136entitled “Torque Reduction Tool,” which are incorporated herein byreference. FIG. 6 depicts one embodiment of the use of drilling dynamicsdata recorder 100 in friction reduction tool 500. Friction reductiontool 500 may include amplifier section 510 in mechanical connection withpulser section 520. Pulser section may include valve section 540 inmechanical and fluid and/or electrical connection with power section530. In the embodiment shown in FIGS. 6 and 6A, drilling dynamics datarecorder 100 may be positioned in friction reduction recorder slot 535.Sensors within friction reduction recorder data dynamics recorder may beused to determine the frequency and intensity of operation of frictionreduction tool 500. Friction reduction recorder slot 535 may be locatedwithin pulser section 520 or amplifier section 510. As shown in FIG. 6 ,friction reduction recorder slot 535 is positioned within amplifiersection 510.

Drilling dynamics data recorder 100, 200 within carrier sub 320 may beused in conjunction with a variety of downhole tool subcomponents thatmake up downhole tool 300. In one non-limiting example, drillingdynamics data recorder 100 may be used with a friction reduction tool,as shown in FIG. 6 and a mud motor, as shown in FIG. 5 . As discussedabove with respect to mud motor 400, one or more of rotor catch recorder425, top sub recorder 485, and bit box recorder 465 may be positioned inmud motor 400. Friction reduction recorder slot 535 may be positionedwithin friction reduction tool 500. As shown in FIG. 7 , frictionreduction tool 500 and mud motor 400 may be mechanically coupled byintermediate drill string section 710. Intermediate carrier sub 550containing drilling dynamics data recorder 100 may be positioned withinintermediate drill string section 710. In certain embodiments, as shownin FIG. 7 , upper carrier sub 545 may be positioned within upper drillstring section 720. The sensors within drilling dynamics data recorders100 within upper carrier sub 545 and intermediate carrier sub 550 may beused to gather data to evaluate transmission of oscillation through bitbox 450 and the drill string.

In another embodiment, drilling dynamics data recorder 100, 200 may bepositioned within a drill bit. In some embodiments, the sensors withindrilling dynamics data recorder 100, 200 may be used to determine bitdynamics and the operating condition of the bit. FIGS. 8A-8D depictlocations in which drilling dynamics data recorders 100 may bepositioned within drill bit 800. FIG. 8A depicts shank slot 810. FIG. 8Bdepicts blade shoulder threaded slot 820. FIG. 8C blade threaded slot830. FIG. 8D depicts body threaded slot 840.

FIG. 9 depicts slots for use with drilling dynamics data recorder 100,200 within drill bit shank 455. In the example shown in FIG. 9 , slot910 and threaded slot 920 are shown for use with drilling dynamics datarecorder 100, 200, respectively.

FIGS. 10A and 10B depict drilling dynamics data recorder 200 instabilizer 1000 and stabilizer 1050, respectively for use in, forexample, a coring or drilling assembly. FIG. 10A depicts drillingdynamics data recorder 200 positioned in blade 1060 of stabilizer body1010. In some embodiments, drilling dynamics data recorder 200 may bepositioned in between adjacent blades 1060 in stabilizer body 1010. FIG.10B depicts drilling dynamics data recorder 200 positioned in blade1060.

FIG. 11 depicts ball seat assembly 1100 for use, for example, with acoring assembly. Ball seat assembly 1100 includes inner bore 1110 inwhich ball seat 1120 is positioned. In the embodiment shown in FIG. 11 ,drilling dynamics data recorder 100, 200 may be positioned within ballseat slot 1130 formed within ball seat outer wall 1140 proximate ballseat 1120. In certain embodiments, a drilling dynamics data recorder100, 200 may be positioned within near bit stabilizer 1000, 1050 asdiscussed herein above, and another drilling dynamics data recorder 100,200 positioned within ball seat assembly 1100. The drilling dynamicsdata recorder 100, 200 within near-bit stabilizer 1000, 1050 may measureshock, vibration, rotation speed (in RPM), inclination, toolface, totalgravity field, radial acceleration, tangential acceleration or acombination thereof, for example. Sensor measurements taken by sensorswithin near-bit stabilizer 1000, 1050 in combination with sensormeasurements taken by sensors within ball seat assembly 1100 maydetermine drilling dynamics throughout the coring assembly.

FIG. 12 depicts drilling dynamics data recorder 100, 200 positionedwithin stick-slip mitigation tool 1200 in stick-slip tool slot 1210.Stick-slip mitigation tool 1200 may also be referred to as a constantweight-on-bit tool. FIG. 13 depicts drilling dynamics data recorder 100,200 positioned within turbine 1300 in turbine slot 1310. In someembodiments, drilling dynamics data recorder 100, 200 may be positionedwithin rotor 1315, stator 1320, or output shaft 1325 of turbine 1300.

In operation, downhole tool 300 is located within the wellbore. Duringthe drilling process, the sensors in sensor package 110 may measuredrilling dynamics data; the drilling dynamics data may be stored inmemory module 115, referred to herein as “memory logging.” When downholetool 300 is retrieved from the wellbore, drilling dynamics data may beretrieved from memory module 115 through communication port 120 for useby a surface processor. The surface processor may use the drillingdynamics data for post-run evaluation of drilling dynamics, frequencyspectrum, statistical analysis, and Condition BasedMonitoring/Maintenance (CBM). In some embodiments, frequency spectrumanalysis may be done, for example, by applying discrete Fouriertransform (or fast Fourier transform) to burst data. In someembodiments, statistical analysis may be done, for example, calculatingminimum, maximum, median, mean, mode, standard deviation, and varianceof burst data. Statistical analysis may include making histograms of,for example, temperature, vibration, shock, inclination, rotation speed,rotation speed standard deviation, and vibration/shock standarddeviation. Temperature histograms may include, for example, accumulatingthe data points in certain temperature bins over multiple deployments(runs) of the sensors and downhole tools.

CBM is maintenance performed when a need for maintenance arises. Thismaintenance is performed after one or more indicators show thatequipment is likely to fail or when equipment performance deteriorates.CBM may apply systems that incorporate active redundancy and faultreporting. CBM may also be applied to systems that lack redundancy andfault reporting.

CBM may be designed to maintain the correct equipment at the right time.CBM may be based on using real-time data, recorded data, or acombination of real-time and recorded data to prioritize and optimizemaintenance resources. Observing the state of a system is known ascondition monitoring. Such a system will determine the equipment'shealth, and act when maintenance is necessary. Ideally, CBM will allowthe maintenance personnel to do only the right things, minimizing spareparts cost, system downtime and time spent on maintenance.

Drilling dynamics data, such as high-frequency continuously sampled andrecorded data, wherein high-frequency data refers to data at 800 Hz-3200Hz, may be used for rock mechanics analysis. Such rock mechanicsanalysis include the analysis/identification of fractures, fracturedirections, rock confined/unconfined compressive strength, Young'smodulus of elasticity, and Poisson's ratio. Such rock mechanics analysismay be accomplished by combining with surface measured parameters, suchas WOB (weight on bit), TOB (torque on bit), RPM (revolutions perminute), ROP (rate of penetration), and flow rate. Pseudoformation-evaluation log, such as pseudo-sonic log, pseudo-neutron log,may be generated with a combination of the analysis of high-frequencycontinuously sampled and recorded data, along with surface parameters,and other formation-evaluation data, such as natural Gamma log and otherlogging-while-drilling (LWD) logs. Alternatively, high-frequencycontinuously-sampled data (e.g. at 800 Hz-3200 Hz) may be used forreal-time rock mechanics analysis.

Power from electrical energy source 130 may be supplied to the sensorsin sensor package 110. In some embodiments, the electrical power fromelectrical energy source 130 to the sensors in sensor package 110 isalways on (powered up) but at different levels. At the lowest powerlevel, which in some embodiments may be used while drilling dynamicsdata recorder 100, 200 are being transported, drilling dynamics datarecorder 100, 200 may be in “deep-sleep mode.” In deep sleep mode, thereal-time clock, sensors, for example, sensors 111, 112, 113, 114, 116,117 and 118, memory module 115, and voltage regulator are powered offand processor 105 is placed in sleep mode. In certain embodiments,current consumption of this deep-sleep mode may be between 1 uA and 200uA. In sleep mode, processor 105 does not function, except to receive a“wake-up” signal. The wake-up signal may, in some embodiments, bereceived through communication port 120. In some embodiments, drillingdynamics data recorder 100, 200 may be placed in deep sleep mode by asoftware command to processor 105 through communication port 120.Drilling dynamics data recorder 100, 200 may be transitioned fromdeep-sleep mode to standby mode by communicating the wake-up signal toprocessor 105 through communication port 120 while processor 105 is inpassive mode. One non-limiting example of the wake-up signalimplementation is to use a communication interrupt feature of processor105 on communication port bus 176. One non-limiting example of processor105 with such feature is a 16-bit microcontroller, Model SM470R1B1M-HTfrom Texas Instruments (Dallas, Tex., USA).

Deep-sleep mode allows extension of battery life during transportationand/or storage without requiring physical disassembly of drillingdynamics data recorder 100, 200. Physical disassembly of drillingdynamics data recorder 100, 200 may damage seals, threads, wires, andother elements if done by unfamiliar technician in a remote location.The recorder may be in “deep-sleep mode” for as much as between 1 monthand 1 year before it is sent downhole for dynamics data logging.

In standby mode, processor 105 and at least one sensor (active sensor)of sensor package 110 are active. Digital solid-state sensors may be putinto standby mode using a digital command. Standby current to remainingsensors of sensor package 110 may be around 1 μA to 200 uA. Once anactive mode predetermined event criterion is met, as determined, forexample, by the active sensor, processor 105 sends a command to theremaining sensors of sensor package 110 to begin measurement of data andto memory module 115 to begin logging data (“active mode”).

FIG. 14 is a block diagram of an embodiment of drilling dynamics datarecorder 100, 200. Drilling dynamics data recorder 100, 200 may includesensor package 110 having a plurality of sensors.

The active mode predetermined event criterion may be, for example, atemperature, acceleration, acceleration standard deviation, rotationspeed standard deviation, or inclination threshold as determined by theactive sensor. The active mode predetermined event may also be a drillstring or bit rotation rate threshold. In some embodiments, the activemode predetermined event criterion may be a combination of one or moreof a temperature threshold, acceleration threshold, accelerationstandard deviation threshold, rotation speed standard deviationthreshold, inclination threshold, drill string rotation rate threshold,or bit rotation rate threshold. In some embodiments, the active modethreshold that predetermines event criterion may be stored in digital,solid-state sensors, which may generate interrupt events to processor105. For example, one non-limiting example of a digital, solid-statesensor with such feature is an I²C digital temperature sensor, ModelMCP9800 from Microchip (Chandler, Ariz., USA). Temperature thresholdswith hysteresis (e.g. upper threshold and lower threshold) may be storedin MCP9800. In certain embodiments, all sensors are non-active duringstandby mode and the drill string or bit rotation (using accelerometers,gyros, magnetometers or a combination thereof) may be communicated toand received by drilling dynamics data recorder 100, 200 via downlinkcommunication from the surface. In certain embodiments, downlinkcommunication may be accomplished by mud-pulse telemetry,electro-magnetic (EM) telemetry, wired-drill-pipe telemetry or acombination thereof. In other embodiments, downlink communication may beaccomplished by varying the drill string rotation rate, for example andnot limited to the method described in U.S. Patent Application No.62/303,931, entitled System and Method for Downlink Communication, filedMar. 4, 2016.

In certain embodiments, during active mode, once a predetermined passivemode criterion has been met, processor 105 may send a command to thesensors of sensor package 110 and memory module 115 to return to standbymode, thereby discontinuing measurement of data by the sensors andlogging of data by memory module 115. The passive mode predeterminedevent criterion may be, for example, a temperature threshold,acceleration threshold, acceleration standard deviation threshold, RPMthreshold, or inclination threshold as determined by one or more sensorsof sensor package 110. In some embodiments, the passive mode thresholdsthat predetermine event criterion may be stored in digital, solid-statesensors, which may generate interrupt events to processor 105. Onenon-limiting example of digital, solid-state sensor with such feature isan I²C digital temperature sensor, Model MCP9800 from Microchip(Chandler, Ariz., USA). Temperature thresholds with hysteresis (e.g.upper threshold and lower threshold) may be stored in MCP9800. In onenon-limiting example, the digital, solid state sensor made may changefrom the passive mode (no logging) to the active mode (logging) and fromthe active mode (logging) to the passive mode (no logging) multipletimes, based on one or more, or a combination of event thresholds.

In active mode, sensors in sensor package 110 are turned on for apredetermined duration at a predetermined log interval for measurementof drilling dynamics data. Examples of predetermined duration include1-10 seconds. Examples of predetermined log intervals are every 1, 2, 5,10, 20, 30, or 60 seconds and durations between those values.Predetermined log intervals for each of the sensors in sensor package110 may be the same or different. Predetermined durations for each ofthe sensors in sensor package 110 may be the same or different.

In certain embodiments, the sensors of sensor package 110 record burstdata to memory module 115 at a burst data frequency. In someembodiments, the burst data frequency may, for example and withoutlimitation, be 20 Hz or more, 50 Hz or more, 100 Hz or more, 200 Hz ormore, 400 Hz or more, 800 Hz or more, 1600 Hz or more, or 3200 Hz ormore. Examples of burst data log interval include every 1, 2, 5, 10, 20,30, or 60 seconds. The sensor burst data may be buffered in digitalsensors in the built-in sensor memory, which may be configured as FIFO(first-in first-out) memory. In certain embodiments, processor 105 doesnot store sensor burst data in processor's RAM (random access memory),i.e., sensor data is sent directly from the sensors in sensor package110 to memory module 115. In certain embodiments, processor 105 maystore a predetermined number of samples of sensor burst data (forexample, just one sample of sensor burst data) in the RAM of processor105 prior to sending the sensor burst data to memory module 115. Inother embodiments, high-frequency sampling data, for example, at 3200Hz, is continuously stored to memory module 115, such as continuouslybursting and recording.

The use of the FIFO memory of a sensor may reduce processor 105processing capability requirements and processor 105 power consumption.In certain embodiments, the number of the FIFO memories of a sensor maybe between 32 and 1025 data points, or between 32 and 512 data pointsper sensor axis. One FIFO memory may hold, for example, 16 bits or 32bits, depending on the sensor output resolution. For example, a 3-axissensor may contain up to 16-bit×100-points×3-axis=48000 bits of FIFOmemory. In some embodiments, the sensors of sensor package 110 mayrecord statistics of some or each of the sensors. For example, thestatistics of the high-g 3-axis accelerometer data, such as minimum,maximum, mean, median, root-mean-squared, standard deviation, andvariance values may be recorded by the sensor package and, in certainembodiments, transmitted to memory module 115. In some embodiments,sensor package 110 may record burst data of the low-g 3-axis digitalaccelerometer data and 3-axis digital gyroscope. In other embodiments,sensor package 110 may record continuously sampled data, for example, at1600 Hz, of the 3-axis digital accelerometer data and 3-axis digitalgyroscope. Raw analog-to-digital counts for accelerometers andgyroscopes, i.e., a number representing voltage, may be recorded inmemory module 115 without temperature calibration or conversion to finalunits. In certain embodiments, temperature calibration may be performedby processor 105 for drilling dynamics data measured by the sensors ofsensor package 110. Temperature calibration may correct for the scaledrift factor and offset drift over temperature. In certain embodiments,temperature calibration may be accomplished, for example, by look-uptables.

In some embodiments, ranges of some or all of the sensors in sensorpackage 110 may be changed while drilling dynamics data recorder 100,200 is within the wellbore. For example, the low-G accelerometer sensingrange is programmable and changeable downhole from +/−4 G to +/−16 G andall ranges therebetween. Ranges may be changed based on attainment of apredetermined range threshold value or by communication by downlink fromthe surface. Examples of predetermined range thresholds include, but arenot limited to values of rotation speed standard deviation, accelerationstandard deviation, or combinations thereof.

In certain embodiments, sampling frequency of some or all of the sensorsin sensor package 110 may be changed while drilling dynamics datarecorder 100, 200 is within the wellbore. Sample frequency may bechanged based on attainment of a predetermined sampling threshold valueor by communication by downlink from the surface. Examples ofpredetermined sampling thresholds include, but are not limited to,values of rotation speed standard deviation, acceleration standarddeviation, or combinations thereof.

In some embodiments, some or all of the sensors in sensor package 110may include an anti-aliasing filter on one or all of the axes of thesensor. The frequency of the anti-aliasing filter may be changed whiledrilling dynamics data recorder 100, 200 is within the wellbore. Forexample, the anti-aliasing filter may be changed to between 25 Hz and3200 Hz for accelerometers. In some embodiments, the anti-aliasingfilter frequency may be changed when sampling frequency is changed toavoid aliasing.

In some embodiments, drilling dynamics data recorder 100, 200communicates with an MWD tool through communications port 120. In onenon-limiting example, statistics of downhole dynamics data (for example,maximum shock, RPM standard deviation, mean vibration, medianinclination, etc.) may be transmitted to surface via an MWD mud-pulsetelemetry, electro-magnetic (EM) telemetry, EM short-hop telemetry,wired-drill-pipe telemetry or a combination thereof.

In some embodiments, drilling dynamics data recorder 100, 200 may bepositioned in an existing downhole tool. In some embodiments, drillingdynamics data recorder 100, 200 may be added to the existing downholetool without altering the tool length or mechanical integrity of thetool. In some such embodiments, a slot as described herein above may beformed in one or more components of the existing downhole tool, and oneor more drilling dynamics data recorders 100, 200 may be placed therein.

FIG. 17 depicts bearing assembly 1100. FIG. 18 depicts bearing assembly1100 having one or more drilling dynamics data recorders 200 consistentwith at least one embodiment of the present disclosure. Bearing assembly1100 may be used to couple driveshaft 1101 to power section 1151 of adrilling string for use in a wellbore. In some embodiments, driveshaft1101 may include bit box 1103 positioned at a lower end of driveshaft1101. As used herein, the terms “upper” and “lower” refer to relativedirections while bearing assembly 1100 is positioned within a wellboretowards the surface and away from the surface respectively. Bit box 1103may, for example and without limitation, be used to couple a drillingbit to driveshaft 1101. In some embodiments, driveshaft 1101 may includecoupler 1105 for coupling driveshaft 1101 to a shaft such as atransmission shaft of a power section such as an electric motor,turbine, or positive displacement mud motor.

In some embodiments, bearing assembly 1100 may include upper bearinghousing 1107. Upper bearing housing 1107 may include upper bearinghousing outer surface 1109. Upper bearing housing outer surface 1109 maybe generally cylindrical. The cylindrical surface of upper bearinghousing outer surface 1109 may define bearing housing longitudinal axisA_(H). Upper bearing housing 1107 may include upper bearing housing bore1111 formed therethrough defining upper bearing housing inner surface1113. In some embodiments, upper bearing housing inner surface 1113 maybe generally cylindrical. The cylindrical surface of upper bearinghousing inner surface 1113 may define bore longitudinal axis A_(B). Insome embodiments, bearing housing longitudinal axis A_(H) and borelongitudinal axis A_(B) may intersect at a point denoted bend point ⊕.In some embodiments, upper bearing housing bore 1111 may be formed suchthat bore longitudinal axis A_(B) is at an angle to bearing housinglongitudinal axis A_(H), denoted angle α in FIG. 18 .

In some embodiments, bearing assembly 1100 may include lower bearinghousing 1115. Lower bearing housing 1115 may be mechanically coupled toupper bearing housing 1107. In some embodiments, lower bearing housing1115 may be mechanically coupled to upper bearing housing 1107 by arepeatable connection such as a threaded coupling depicted in FIG. 18 asthreaded interface 1117, which may form a fluid seal as discussed hereinbelow. Lower bearing housing 1115 may include lower bearing housing bore1119 formed therethrough defining lower bearing housing inner surface1121. Lower bearing housing bore 1119 and upper bearing housing bore1111 may be connected and substantially concentric along borelongitudinal axis A_(B).

In some embodiments, driveshaft 1101 may be positioned within upperbearing housing bore 1111 and lower bearing housing bore 1119.Driveshaft 1101 may be tubular and may extend substantially along borelongitudinal axis A_(B). Driveshaft 1101 may be rotatable within upperbearing housing 1107 and lower bearing housing 1115.

In some embodiments, one or more bearings may be positioned betweendriveshaft 1101 and one or both of upper bearing housing 1107 and lowerbearing housing 1115. For example, in some embodiments, one or moreradial bearings such as upper radial bearing 1123 may be positionedbetween driveshaft 1101 and upper bearing housing inner surface 1113 andlower radial bearing 1125 may be positioned between driveshaft 1101 andlower bearing housing inner surface 1121. Upper radial bearing 1123 andlower radial bearing 1125 may, for example and without limitation,reduce friction between driveshaft 1101 and upper and lower bearinghousings 1107, 1115 while driveshaft 1101 is rotated. Upper radialbearings 1123 and lower radial bearings 1125 may resist lateral forcebetween driveshaft 1101 and upper and lower bearing housings 1107, 1115during a drilling operation. Because driveshaft 1101 is at angle α tothe direction weight is applied to the drill bit, lateral forces may beapplied against upper radial bearings 1123 and lower radial bearings1125. In some embodiments, by forming upper radial bearings 1123 andlower radial bearings 1125 as oil bearings as discussed further hereinbelow, greater forces may be exerted on upper radial bearings 1123 andlower radial bearings 1125 than in an embodiment utilizing drillingfluid cooled bearings. In some embodiments, one or more thrust bearings1127 may be positioned between driveshaft 1101 and one or both of upperand lower bearing housings 1107, 1115. Thrust bearings 1127 may, forexample and without limitation, resist longitudinal force on driveshaft1101 such as weight on bit during a drilling operation. In someembodiments, upper radial bearings 1123, lower radial bearings 1125, andthrust bearings 1127 may each include one or more of, for example andwithout limitation, diamond bearings, ball bearings, and rollerbearings.

In some embodiments, one or more of upper radial bearing 1123, lowerradial bearing 1125, and thrust bearings 1127 may be oil-lubricatedbearings. In such an embodiment, the annular portion of upper bearinghousing bore 1111 and lower bearing housing bore 1119 about driveshaft1101 may be filled with oil. In some such embodiments, upper bearinghousing bore 1111 may include piston 1129. Piston 1129 may be an annularbody adapted to seal between driveshaft 1101 and upper bearing housinginner surface 1113 and slidingly traverse longitudinally. In some suchembodiments, piston 1129 may separate upper bearing housing bore 1111into an oil filled portion, denoted 1131 and a drilling fluid filledportion denoted 1133. In some such embodiments, drilling fluid filledportion 1133 may be fluidly coupled to upper bearing housing bore 1111such that pressure from drilling fluid positioned therein causes acorresponding increase in pressure within oil filled portion 131,thereby pressure balancing the oil lubricating one or more of upperradial bearing 1123, lower radial bearing 1125, and thrust bearings 1127with the surrounding wellbore. In some embodiments, one or more seals1135 may be positioned between one or more of driveshaft 1101 and lowerbearing housing 1115, driveshaft 1101 and upper bearing housing 1107,driveshaft 1101 and piston 1129, and piston 1129 and upper bearinghousing 1107. In some embodiments, one or more fluid paths 1134 may bepositioned to fluidly couple between upper bearing housing bore 1111 andfluid filled portion 1133. In some such embodiments, fluid paths 1134may provide resistance to fluid flowing into fluid filled portion 1133to, for example and without limitation, reduce fluid loss. In otherembodiments, one or more high pressure seals may be positioned betweenpiston 1129 and upper bearing housing bore 1111, and fluid paths 1134may not need to produce the resistance as described. In someembodiments, because oil-filled portion 131 is sealed from fluid filledportion 1133, bearing assembly 1100 may be utilized with an air drillingoperation or with highly abrasive or corrosive drilling fluid withoutcompromising upper radial bearing 1123, lower radial bearing 1125, andthrust bearings 1127.

In some embodiments, because driveshaft 1101 is longitudinally alignedwith and rotates along bore longitudinal axis A_(B), driveshaft 1101 andany bit coupled to bit box 1103 thereof may rotate at angle α relativeto bearing housing longitudinal axis A_(H), and may therefore allow fora wellbore drilled thereby to be steered in a direction correspondingwith the direction of angle α, defining a toolface of bearing assembly1100. In some embodiments, bend point ⊕ may be positioned at a locationnearer to bit box 1103 than coupler 1105 of driveshaft 1101. Positioningbend point ⊕ nearer to bit box 1103 may, for example and withoutlimitation, allow a drill bit coupled to bit box 1103 to be positionedcloser to bearing housing longitudinal axis A_(H) while remainingoriented at angle α to bearing housing longitudinal axis A_(H) than anembodiment in which bend point ⊕ is positioned closer to coupler 1105.

As shown in FIGS. 18 and 20 , in some embodiments, upper bearing housing1107 may include bit box slot 1112 b formed therein and positionedadjacent to or within bit box 1103. In some embodiments, bearing housingslot 1112 a may be formed in upper bearing housing 1107 at a radialorientation generally corresponding with the thickest portion of upperbearing housing 1107. In some embodiments, drilling dynamics datarecorders 200 may be positioned within slots 1112 a, 1112 b. As shown inFIG. 21 , a third slot 1112 positioned within top sub 1149, top sub slot1112 c may house drilling dynamics data records 200.

In some embodiments, as depicted in FIG. 19 , bearing assembly 1100 maybe coupled to transmission housing 1137 forming BHA. Transmissionhousing 1137 may couple between upper bearing housing 1107 and powersection 1151 which may include a downhole motor such as a mud motor,turbine, gear-reduced turbine, or electric motor. Transmission shaft1139 may be positioned within transmission housing 1137 and may coupleto coupler 1105 of driveshaft 1101 to, for example and withoutlimitation, transfer rotational power to driveshaft 1101. In someembodiments, transmission housing 1137 may be formed such that itincludes a bend and therefore forms bent sub 1141. In some embodiments,the direction of bend of bent sub 1141 may be positioned such that it isaligned with the toolface of bearing assembly 1100, thereby increasingthe effective bend of bearing assembly 1100. In some embodiments, ascribe line may be formed on an outer surface of one or both of bearingassembly 1100 and transmission housing 1137 in alignment with thedirection of bend such that bearing assembly 1100 and transmissionhousing 1137 may be properly aligned. In some embodiments, timing ring1142 may be positioned between transmission housing 1137 and bearingassembly 1100 to ensure the alignment. In some embodiments, as depictedin FIG. 19 , bearing assembly 1100 or transmission housing 1137 mayinclude contact pad 1143 on an outer surface thereof. In someembodiments, contact pad 1145 may be positioned on a side of bearingassembly 1100 or transmission housing 1137 opposite the toolfacethereof. Contact pads 1143, 1145 may contact the surrounding wellboreand may, for example and without limitation, assist with directionaldrilling. Top sub 1149 may be positioned above power section 1151.

In yet another embodiment, drilling dynamics data recorder 100, 200 maybe positioned in a steering tool. Non-limiting examples of steeringtools include a vertical and directional tool, as described hereinbelow. As shown in FIG. 16 , steering tool 1400 may include uppermandrel 1410, substantially non-rotating housing 101, and bit box 14. Inthe embodiment shown in FIG. 16 , drilling dynamics data recorders 100,200 may be positioned in upper mandrel slot 1412, substantiallynon-rotating housing slot 1414, bit box slot 1416, or a combinationthereof.

As depicted in FIG. 22 , downhole steering tool 2100 may be included aspart of drill string 2010. In some embodiments, downhole steering tool2100 may be included as part of a bottomhole assembly of drill string2010. In some embodiments, downhole steering tool 2100 may be positionedabout mandrel 2012 of drill string 2010. Mandrel 2012 may be coupled todrill bit 2014 within bit box 2020 and adapted to provide rotationalforce thereto to form wellbore 2015. In some embodiments, mandrel 2012may be coupled to drill string 2010 such that rotation of drill string2010 from the surface by, for example and without limitation, a rotarytable or top drive, causes rotation of mandrel 2012. In someembodiments, mandrel 2012 may be coupled to a downhole motor such as amud motor or downhole turbine to provide rotation. Downhole steeringtool 2100 may include housing 2101. In some embodiments, housing 2101may be tubular or generally tubular. Housing 2101 may be positionedabout mandrel 2012 and may be rotatably coupled thereto such thatmandrel 2012 may rotate independently of housing 2101. In someembodiments, for example and without limitation, one or more bearingsmay be positioned between housing 2101 and mandrel 2012. Although shownas a single piece, one having ordinary skill in the art with the benefitof this disclosure will understand that housing 2101 may be formed fromone or more pieces.

In some embodiments, housing 2101 may rotate at a speed that is lessthan the rotation rate of the drill bit and mandrel 2012. For exampleand without limitation, in some embodiments, housing 2101 may rotate ata speed that is less than the rotation speed of mandrel 2012. Forexample and without limitation, housing 2101 may rotate at a speed atleast 50 RPM slower than mandrel 2012. For example and withoutlimitation, in an instance where mandrel 2012 rotates at 51 RPM, housing2101 may rotate at 1 RPM or less. In some embodiments, housing 2101 mayrotate at a speed that is less than a percentage of the rotation speedof mandrel 2012. For example and without limitation, housing 2101 mayrotate at a speed lower than 50% of the speed of mandrel 2012. In someembodiments, housing 2101, by not rotating, may maintain a toolfaceorientation independent of rotation of drill string 2010.

As further shown in FIG. 22 , in certain embodiments, drilling dynamicsdrilling recorder 200 may be positioned within bit box 2014 in slot 2017and within housing 2101 in slot 2019.

In some embodiments, downhole steering tool 2100 may include one or moresteering blades 2103. Steering blades 2103 may be positioned about aperiphery of housing 2101. Steering blades 2103 may be extendible tocontact wellbore 2015. In some embodiments, steering blades 2103 may beat least partially positioned within steering cylinders 2105 and may besealed thereto. Fluid pressure within each steering cylinder 2105 mayincrease above fluid pressure in the surrounding wellbore 2015, therebycausing a differential pressure across the steering blade 2103positioned therein. The differential pressure may cause an extensionforce on steering blade 2103. The extension force on steering blade 2103may urge steering blade 2103 into an extended position. When positionedwithin wellbore 2015, the extension force may cause steering blade 2103to contact wellbore 2015. In some embodiments, steering blade 2103 may,for example and without limitation, at least partially prevent or retardrotation of housing 2101 to, for example and without limitation, lessthan 20 revolutions per hour.

In some embodiments, fluid may be supplied to each steering cylinder2105 through a steering port 2107. In some embodiments, the fluid may bedrilling mud. The fluid in each steering port 2107 may be controlled byone or more adjustable orifices 2109. Fluids may include, but are notlimited to, drilling mud, such as oil-based drilling mud or water-baseddrilling mud, air, mist, foam, water, oil, including gear oil, hydraulicfluid or other fluids within wellbore 2015. Adjustable orifices 2109 maycontrol fluid flow between an interior of mandrel 2012 and steeringports 2107. In some embodiments, each steering cylinder 2105 iscontrolled by an adjustable orifice 2109. In some embodiments, one ormore steering blades 2103 may be aligned about downhole steering tool2100 and may be controlled by the same adjustable orifice 2109. As usedherein, “adjustable orifice” includes any valve or mechanism having anadjustable flow rate or restriction to flow.

Fluid may be supplied to each adjustable orifice 2109 from an interior2013 of mandrel 2012. Adjustable orifice 2109 may be fluidly coupled tothe interior 2013 of mandrel 2012. In some embodiments, for example andwithout limitation, one or more apertures 2111 may be formed in mandrel2012 which may be coupled to each adjustable orifice 2109 allowing fluidto flow to each adjustable orifice 2109 as mandrel 2012 rotates relativeto housing 2101. In some embodiments, as further discussed herein below,a diverter may be utilized.

In some embodiments, adjustable orifices 2109 may be reconfigurablebetween an open position and a partially open position. In someembodiments, adjustable orifices 2109 may further have a closedposition. In the partially open position, adjustable orifices 2109 mayremain partially open such that an amount of fluid may pass into thecorresponding steering cylinder 2105. During certain operations, forinstance to centralize downhole steering tool 2100 within wellbore 2015,as depicted schematically and without limitation as to structure in FIG.2A, each adjustable orifice 2109 a-d may remain in the partially openposition, such that only a portion of the amount of fluid may passtherethrough compared to when an adjustable orifice 2109 is fully open.In some embodiments, the partially open position may allow between 0%and 50% of the flow of the opened position, between 10% and 40% of theflow of the opened position, or between 25% and 35% of the openedposition. Each steering blade 2103 a-d may thus receive a substantiallyequal differential pressure thereacross and may be extended to contactwellbore 2015 with approximately equal extension force, showngraphically as arrows depicting first extension force f Steering blades2103 a-d may thus centralize downhole steering tool 2100 within wellbore2015. In some embodiments, steering blades 2103 a-d may include one ormore anti-rotation features on the end thereof such that when in contactwith wellbore 2015, the force exerted by each steering blade 2103 a-dprevents or retards rotation of downhole steering tool 2100 relative towellbore 2015.

When a steering input is desired, one or more adjustable orifices(depicted as adjustable orifice 2109 a′ in FIG. 24A), may be fullyopened by actuating its corresponding solenoid. The adjustable orifices2109 b-d not in the open position may remain in the partially openposition. With adjustable orifice 2109 a′ in the open position, a largeramount of fluid may flow to the corresponding steering blade (2103 a′ inFIG. 3B), causing the differential pressure thereacross to be higherthan to steering blades 2103 not corresponding to a fully openadjustable orifice 2109, and thus exerting a larger extension force,depicted as second extension force F thereupon. The opposing steeringblade (here 2103 c) (or steering blades depending on configuration)receives a smaller first extension force f, and its extension may be atleast partially overcome by the extension of steering blade 2103 a′,causing downhole steering tool 2100 to be pushed away from wellbore 2015in the direction of steering blade 2103 a′. This second extension forceF may thus cause a change in the direction in which downhole steeringtool 2100 is pushed relative to wellbore 2015, referred to herein as aforce-vector direction, which may alter the direction in which wellbore2015 is drilled.

In some embodiments, when drilling a straight or nearly straightwellbore 2015, in some embodiments, all adjustable orifices 2109 a-d maybe opened, applying substantially equal pressure to all steering blades2103, causing equal force exerted by all steering blades 2103 againstwellbore 2015. Alternatively, minimum gripping force may be exerted byall steering blades 2103 against wellbore 2015 when all adjustableorifices 2109 a-d are partially open.

In some embodiments, as depicted in FIG. 25 , fluid may be supplied fromthe interior of mandrel 2012 (here depicted as having two subcomponentscoupled to either side of diverter assembly 2141) through diverterassembly 2141. The fluid within mandrel 2012 may include, withoutlimitation, drilling mud, such as oil-based drilling mud or water-baseddrilling mud; air; mist; foam; water; oil, including gear oil; hydraulicfluid; or a combination thereof. The fluid within mandrel 2012 may besupplied by one or more pumps at the surface through mandrel 2012 to,for example and without limitation, operate one or more downhole toolsand clear cuttings from wellbore 2015 during a drilling operation. Fluidwithin mandrel 2012 may be at a higher pressure than fluid withinwellbore 2015. Diverter assembly 2141 may include diverter body 2143coupled to and rotatable with mandrel 2012. In some embodiments,diverter assembly 2141 may be formed integrally with mandrel 2012. Insome embodiments, diverter assembly 2141 may contain drilling fluidfilter 2147. Diverter body 2143 may include one or more apertures 111coupling the interior of mandrel 2012 to one or more fluid supply ports2106 formed within housing 2101. Fluid supply ports 2106 may supplyfluid to adjustable orifices as described herein below. In someembodiments, approximately 4-5% of the flow going through the interiorof mandrel 2012 may be diverted through diverter assembly 2141. In someembodiments, a portion of the diverted fluid may pass into one or morebearings and may exit to the annular space about downhole steering tool2100.

In some embodiments, a controller, discussed herein below as controllers2119 and 2237 shown in FIGS. 26A, 27A respectively, may control theactuation of adjustable orifices 2109. For the purpose of thisdescription, controller 2119 will be discussed specifically, althoughone having ordinary skill in the art with the benefit of this disclosurewill understand that controller 2237 may operate similarly. In someembodiments, controller 2119 may be electrically coupled to adjustableorifices 2109.

In some embodiments, controller 2119 may include one or moremicrocontrollers, microprocessors, FPGAs (field programmable gatearrays), a combination of analog devices, such analog integratedcircuits (ICs), or any other devices known in the art. In someembodiments, downhole steering tool 2100 may include differentialrotation sensor 2112, which may be operable to measure a difference inrotation rates between mandrel 2012 and housing 2101, and housingrotation measurement device or sensor 2116, which may be operable tomeasure a rotation rate of housing 2101. For example, in someembodiments, differential rotation sensor 2112 may include one or moreinfrared sensors, ultrasonic sensors, Hall-effect sensors, fluxgatemagnetometers, magneto-resistive magnetic-field sensors,micro-electro-mechanical system (MEMS) magnetometers, and/or pick-upcoils. Differential rotation sensor 2112 may interact with one or moremarkers 2114, such as infrared reflection mirrors, ultrasonicreflectors, magnetic markers, permanent magnets, electro magnets,coupled to mandrel 2012 which may be, for example and withoutlimitation, one or more magnets or electro-magnets to interact with amagnetic differential rotation sensor 2112. Housing rotation measurementdevice or sensor 2116 may include one or more accelerometers,magnetometers, and/or gyroscopic sensors, includingmicro-electro-mechanical system (MEMS) gyros, MEMS accelerometers and/orothers operable to measure cross-axial acceleration, magnetic-fieldcomponents, or a combination thereof. Gyroscopic sensors and/or MEMSgyros may be used to measure the rotation speed of housing 2101 andirregular rotation speed of housing 2101, such as torsional oscillationand stick-slip. The accelerometers and magnetometers in housing 2101 maybe used to calculate the toolface of downhole steering tool 2100. Thetoolface of downhole steering tool 2100 may, in some embodiments, bereferenced to a particular steering blade 2103. In some embodiments, thetoolface of downhole steering tool 2100 may be defined relative to agravity field, known as a gravity toolface; defined relative to amagnetic field, known as a magnetic toolface; or a combination thereof.Differential rotation sensors 2112 and housing rotation measurementdevice or sensors 2116 may be disposed anywhere in the housing 2101.Markers 2114 may be disposed to the corresponding position on mandrel2012, substantially near differential rotation sensors 2112.

When drilling a vertical wellbore 2015, as depicted in FIG. 29 , gravitytoolface may be used. To maintain verticality, gravity toolface (GTF)may be set to the low side of wellbore 2015, corresponding to a 180°gravity toolface, and at least one steering blade 2103 may apply aneccentric force to the side of wellbore 2015 opposite the targettoolface (TF). In some embodiments, the steering blade 2103 may apply aneccentric force to the side of wellbore 2015 substantially opposite thetarget TF, such as, for example and without limitation, within 15° of180° from the target TF.

In some embodiments, in order to drill wellbore 2015 vertically, thetarget gravity tool face (GTF) of downhole steering tool 2100 may be setto the low side of the borehole (GTF=180°). In some embodiments, theequation for the GTF may be given by:

${GTF} = {{\arctan\left( \frac{G_{y}}{G_{x}} \right)}.}$

The accuracy of GTF near vertical may depend on the accuracy of thetransverse acceleration measurements (Gx and Gy).

To form a deviated wellbore, the initial change in direction of wellbore2015, referred to herein as a kick-off from vertical, as depicted inFIG. 30 , may be defined with respect to a magnetic toolface. In someembodiments, at least one steering blade 2103 may apply an eccentricforce to the opposite side of the target toolface against wellbore 2015.

In some embodiments, when vertical or, for example and withoutlimitation, within 5° to 10° of vertical, a magnetic toolface may beused. Above, for example and without limitation, 5° to 10° ofinclination, a gravity toolface may be utilized.

In some embodiments, in vertical kick-off, magnetic toolface (MTF) maybe used to kick off to the desired direction (e.g. referenced tomagnetic field, such as north, south, east, west or magnetic toolface tobe zero, referencing to the magnetic north). The equation for the MTFmay be given by:

${MTF} = {\arctan\left( \frac{M_{y}}{M_{x}} \right)}$

In some embodiments, as housing 2101 rotates, the steering blade orblades 2103 aligned substantially opposite of the target toolfacechanges. Controller 2119 may be configured to actuate either one or twoadjacent steering blades 2103 to apply an eccentric steering force onwellbore 2015 to push downhole steering tool 2100 in a desired directioncorresponding with the target toolface. In some embodiments, thesteering blades 2103 not actuated by controller 2119 may be extended toprovide gripping pressure as they are in the partially open position.For example and without limitation, as depicted in FIGS. 31A-D, ashousing 2101 rotates substantially slowly, e.g. one revolution per hour,steering blades 2103 a-d, as rotated relative to wellbore 2015, aresequentially actuated when oriented opposite the target toolface (TF).In FIG. 31A, steering blade 2103 a is actuated. In FIG. 31B, afterhousing 2101 rotates, steering blades 2103 a and 2103 b are actuated. InFIG. 31C, steering blade 2103 b alone is actuated, and in FIG. 31D,steering blades 2103 b and 2103 c are actuated.

In some embodiments, the target toolface (either MTF or GTF) may bedownlinked to downhole steering tool 2100. In some embodiments, thetarget toolface may be computed based on the target inclination ortarget inclination/azimuth downlinked to downhole steering tool 2100. Insome such embodiments, controller 2119 may use a closed-loop controlsystem for inclination/azimuth hold.

In some embodiments, as depicted in FIG. 26A, each adjustable orifice2109 may be controlled by a corresponding solenoid actuator, referred toherein as solenoid 2115. In some embodiments, each solenoid 2115 may bepositioned within compensated oil compartment 2117. Compensated oilcompartment 2117 may be filled with a fluid such as an oil and preventor restrict drilling fluid or other debris from entering compensated oilcompartment 2117. In some embodiments, compensated oil compartment 2117may be pressurized to a pressure higher than that expected of thesurrounding fluid.

In some embodiments, solenoids 2115 may be controlled by controller2119. In some embodiments, controller 2119 may be electrically coupledto solenoids 2115, and may include electronics configured to actuatesolenoids 2115. In some embodiments, controller 2119 may include or beelectrically coupled to one or more sensors, such as, for example andwithout limitation, accelerometers, gyroscopes, magnetometers, etc., andmay use information detected by the one or more sensors to controlsolenoids 2115. In some embodiments, controller 2119 may includeelectronics for receiving instructions for controlling solenoids 2115.In some embodiments, controller 2119 may include one or more powersupplies, such as, for example and without limitation, batteries 2121,for powering controller 2119 and solenoids 2115. Solenoids 2115 may becoupled to adjustable orifices 2109 by one or more mechanical linkages.Solenoids 2115 may be any type of solenoid known in the art, including,for example and without limitation, push solenoids, pull solenoids,rotary solenoids, and latching solenoids.

In some embodiments, as depicted in FIG. 26B, 26C, solenoid 2115 may becoupled to piston 2123. Piston 2123 may be movable by solenoid 2115,here depicted as a linear push solenoid although other solenoids areencompassed by this disclosure. Piston 2123 may be positioned withinvalve cylinder 2125. Valve cylinder 2125 may include two or more inputports 2127 a-c that are fluidly coupled with fluid supply ports 2106 asdiscussed herein above in fluid communication with the interior ofmandrel 2012. Valve cylinder 2125 may also include output ports 2129 a-cthat are fluidly coupled to steering port 2107. In some embodiments,input ports 2127 a-c may be aligned with output ports 2129 a-c. In someembodiments, piston 2123 may include one or more radial grooves 2131a-c. Radial grooves 2131 a-c may fluidly couple corresponding inputports 2127 a-c and output ports 2129 a-c when the corresponding radialgroove 2131 a-c is aligned therewith as depicted in FIG. 26B (the “open”position), and close fluid communication therebetween when not alignedtherewith by movement of piston 2123 by solenoid 2115 as depicted inFIG. 26C (the “partially open” position). In some embodiments, one ormore of radial grooves 2131 a-c (here depicted as radial groove 2131 a)may be of a sufficient width such that fluid communication between thecorresponding ports, here input port 2127 a and output port 2129 a, isopen when piston 2123 is in the partially open position, as depicted inFIG. 26C where radial groove 2131 a is wider than radial grooves 2131b-c. In such an embodiment, when in the open position, i.e. adjustableorifice 2109 is open, more fluid is able to flow through than when inthe partially open position, i.e. adjustable orifice 2109 is partiallyopen, as all input ports 2127 a-c are fluidly coupled to output ports2129 a-c, rather than only one input port 2127 a to output port 2129 ain the partially open position. One having ordinary skill in the artwith the benefit of this disclosure will understand that any number ofinput ports and output ports may be utilized without deviating from thescope of this disclosure, and any number of ports may remain fluidlycoupled in the closed position without deviating from the scope of thisdisclosure. In some embodiments, the number of ports may be selectedsuch that the force required to actuate solenoid 2115 is within adesired limit.

In some embodiments, as depicted in FIGS. 27A-C, adjustable orifices2109′ may be controlled by ring valve 2215. Ring valve 2215, may includemanifold 2217 and valve ring 2231. Manifold 2217 may include adjustableorifices 2109′ defining manifold orifices 2221 arranged about uppermanifold surface 219. Each manifold orifice 2221 may be coupled to acorresponding steering port 2107. Fluids controlled by ring valve 2215may include, but are not limited to, drilling mud, such as oil-baseddrilling mud or water-based drilling mud, air, mist, foam, water, oil,including gear oil, hydraulic fluid or other fluids within mandrel 2012.

Valve ring 2231 may be generally annular. Valve ring 2231 may be rotatedby one or more motors 2235. In some embodiments, motor 2235 may be anelectric motor, such as, for example and without limitation, a brushlessDC (direct current) motor. In some embodiments, motor 2235 may becontrolled by controller 2237. In some embodiments, controller 2237 mayinclude electronics configured to actuate motor 2235. In someembodiments, controller 2237 may include one or more sensors, such as,for example and without limitation, accelerometers, gyroscopes,magnetometers, etc., and may use information detected by the one or moresensors to control motor 2235. In some embodiments, valve ring 2231 mayinclude one or more position markers 2254 such as magnetic markers ormagnets. Controller 2237 may include one or more valve ring positionsensors 2256 to determine the position of valve ring 2231. Valve ringposition sensors 2256 may include, for example and without limitation,one or more pick up coils, magnetometers, Hall-effect sensors,mechanical position sensors, or optical position sensors. In someembodiments, controller 2237 may include electronics for receivinginstructions for controlling motor 2235. In some embodiments, controller2237 may include one or more power supplies, such as, for example andwithout limitation, batteries 2239, for powering controller 2237 andmotor 2235. Motor 2235 may be coupled to valve ring 2231 by one or moremechanical linkages such as gearbox 2232 which may include, for exampleand without limitation, drive ring 2233 and pinion 2241 or otherlinkages. In some embodiments, valve ring 2231 may be coupled to orformed as part of a rotor of motor 2235.

Controller 2237 may include, for example and without limitation, one ormore microcontrollers, microprocessors, FPGAs (field programmable gatearrays), a combination of analog devices, such analog integratedcircuits (ICs), or any other devices known in the art, which may beprogrammed with motor controller logic and algorithms, including angularposition controller logic and algorithms.

In some embodiments, valve ring 2231 may include one or more slots 2243formed on lower ring surface 2245 thereof (shown in FIG. 27C). Lowerring surface 2245 may abut or be positioned in abutment with uppermanifold surface 2219 such that when a slot 2243 is aligned with amanifold orifice 2221 of manifold 2217, fluid may flow through manifoldorifice 2221 from fluid supply port 2247 coupled to the interior ofmandrel 2012 as previously discussed herein. Valve ring 2231 may berotated by motor 2235, moving slots 2243 into and out of alignment withadjustable orifices 2109′. In some embodiments, valve ring 2231 may berotatable by one or more full revolutions. In some embodiments, slots2243 may be arranged such that valve ring 2231 needs only rotate apartial turn to actuate each of adjustable orifices 2109′. In someembodiments, slots 2243 may be arranged about valve ring 2231 such thatadjustable orifices 2109′ opposite one another are not open at the sametime. In some embodiments, slots 2243 may be arranged such that adjacentadjustable orifices 2109′ may be opened at the same time.

In some embodiments, lip 2249 may be formed in lower ring surface 2245of valve ring 2231. Lip 2249 may be positioned such that lower ringsurface 2245 of valve ring 2231 partially blocks a manifold orifice 2221when aligned with lip 2249 and not with slot 2243, thereby partiallyopening the manifold orifice 2221. In some embodiments, lip 2249 may bediscontinuous such that all manifold orifices 2221 may be fully closedin a certain position of valve ring 231.

For example, FIGS. 7A-J depict an exemplary valve ring 2231 (insemitransparent view) positioned manifold 2217. Each drawing depictsvalve ring 2231 rotated to a different angular position and with slots2243 opening or closing one or more of manifold orifices 2221 a-d asoutlined in the following table.

TABLE 1 Ring Valve Positions FIGS. 28A-28J Valve Ring FIG. AngularOrifice 1 Orifice 2 Orifice 3 Orifice 4 # Position (221a) (221b) (221c)(221d) 7A  0° OPEN PARTIALLY PARTIALLY PARTIALLY OPEN OPEN OPEN 7B  5°*PARTIALLY PARTIALLY PARTIALLY PARTIALLY OPEN OPEN OPEN OPEN 7C 10° OPENOPEN PARTIALLY PARTIALLY OPEN OPEN 7D 20° PARTIALLY OPEN PARTIALLYPARTIALLY OPEN OPEN OPEN 7E 30° PARTIALLY OPEN OPEN PARTIALLY OPEN OPEN7F 40° PARTIALLY PARTIALLY OPEN PARTIALLY OPEN OPEN OPEN 7G 50°PARTIALLY PARTIALLY OPEN OPEN OPEN OPEN 7H 60° PARTIALLY PARTIALLYPARTIALLY OPEN OPEN OPEN OPEN 7I 70° OPEN PARTIALLY PARTIALLY OPEN OPENOPEN 7J 80° CLOSED CLOSED CLOSED CLOSED

In some embodiments, although described as at a 5° offset of valve ring2231, the position shown in FIG. 28B in which each manifold orifice 2221a-d is partially closed may be between any of the other positions, suchas at 150, 250, etc. In some embodiments, though not depicted, aposition of valve ring 2231 may include slots 2243 such that in aposition, all manifold orifices 2221 a-d are open. The position shown inFIG. 7B (all manifold orifices 2221 a-d being partially open) may beused to create a substantially neutral steering tendency of downholesteering tool 2100 by exerting the same amount of force on each steeringblade 2103, and in some embodiments, this valve position is used todrill a substantially straight borehole, including and but not limitedto long tangent sections and horizontal sections, with some droptendency compensation and course correction. Additionally, in someembodiments, the extension of each steering blade 2103 by the sameamount of force may cause all steering blades 2103 to contact wellbore2015 and grip thereagainst, thereby, for example and without limitation,reducing rotation of slowly rotating housing 2101.

In some embodiments, as depicted in FIG. 32 , valve ring 2231′ mayinclude one or more slots 2243′ which may include taper 2244′. Taper2244′ may, when aligned with manifold orifices 221 a-d, partially openone or more of manifold orifices 221 a-d depending on the rotationalposition of valve ring 2231′. Therefore, each of manifold orifices 221a-d may be partially opened and closed as valve ring 2231′ is rotated.In some embodiments, taper 2244′ may be formed in lip 2249′. In someembodiments, as valve ring 2231′ is rotated, steering blades 2103 a-d aspreviously discussed may be extended with variable force depending onhow much of the respective manifold orifice 2221 a-d is opened by taper2244′. In some embodiments, the rotation of valve ring 2231′ may becontrolled, for example and without limitation, such that it isrotatable to a known degree increment, referred to herein as a “step.”In some embodiments, for example and without limitation, each step maybe 0.2°, thereby allowing a fine adjustment of the force-vectordirection imparted by steering blades 2103 a-d controlled by manifoldorifices 2221 a-d respectively. For example, where, as discussed hereinabove, adjacent valve ring angular positions are separated by 10°, a0.2° step would allow 50 intermediate positions of valve ring 2231′ tobe reached. The force-vector direction imparted by steering blades 2103a-d may, in such an embodiment, therefore be controlled at 0.9°increments or having 400 discrete force-vector directions. One havingordinary skill in the art with the benefit of this disclosure willunderstand that by changing the degree increment of the step, the numberof discrete force-vector directions may be modified without deviatingfrom the scope of this disclosure. The ability to finely adjust theforce-vector direction of downhole steering tool 2100 may thereby allowthe force-vector direction to be adjusted at a fine increment to, forexample and without limitation, align with the desired direction ofpropagation of wellbore 2015.

In some embodiments, the rotation of valve ring 2231′ between a positionin which one or more manifold orifices 2221 a-d are open to a positionin which one or more manifold orifices 2221 a-d are closed may require alarge amount of torque on motor 2235. This increase in torque requiredmay, for example and without limitation, require a higher peak currentand therefore larger amount of power to be supplied to motor 2235. Thisincrease in torque required due to the increasing pressure drop acrossmanifold orifices 2221 a-d as they are closed may, for example andwithout limitation, cause valve ring 2231′ to get stuck, jam, orotherwise not be able to close the respective manifold orifice 2221 a-d.

In some embodiments, as depicted in FIG. 34 , valve ring 2231′ may berotated to different angular positions (labeled A-J) such that slots2243′ open or close one or more of manifold orifices 22 21 a-d asoutlined in Table 2 below:

TABLE 2 Ring Valve Positions FIG. 34 Valve Ring Angular Orifice 1Orifice 2 Orifice 3 Orifice 4 Position Position (221a) (221b) (221c)(221d) A  0° OPEN CLOSED CLOSED CLOSED B  9° OPEN OPEN CLOSED CLOSED C18° CLOSED OPEN CLOSED CLOSED D 27° CLOSED OPEN OPEN CLOSED E 36° CLOSEDCLOSED OPEN CLOSED F 45° CLOSED CLOSED OPEN OPEN G 54° CLOSED CLOSEDCLOSED OPEN H 63° OPEN CLOSED CLOSED OPEN I 74° CLOSED CLOSED CLOSEDCLOSED J 81° OPEN OPEN OPEN OPEN

In such an embodiment, with reference to FIG. 33 , slots 2243′ may allowall manifold orifices 2221 a-d to be fully opened when valve ring 2231′is positioned such that manifold orifices 2221 a-d are aligned with, forexample and without limitation, the 81° position denoted J in FIG. 34 .Position J may be positioned radially adjacent to a position in whichall manifold orifices 2221 a-d are fully closed, such as, for exampleand without limitation, the 74° position denoted I in FIG. 13 . In someembodiments, each slot 2243′ may include taper 2244″ allowing, forexample and without limitation, valve ring 2231′ to gradually close therespective manifold orifice 2221 a-d to be closed as valve ring 2231′rotates between positions. Tapers 2244″ may, for example and withoutlimitation, reduce the torque required to move valve ring 2231′ whenclosing manifold orifices 2221 a-d, and thereby reducing the chance ofvalve ring 2231′ getting stuck or jammed as valve ring 2231′ is movedbetween positions and reducing peak current or power supplied to themotor 2235.

In some embodiments, valve ring 2231″ as depicted in FIG. 35 may operatesubstantially as described with respect to FIG. 34 , such that valvering 2231″ may be rotated to different angular positions (labeled A-J)such that slots 2243″ open, partially open, or close one or more ofmanifold orifices 2221 a-d as outlined in Table 3 below:

TABLE 3 Ring Valve Positions FIG. 35 Valve Ring Angular Orifice 1Orifice 2 Orifice 3 Orifice 4 Position Position (221a) (221b) (221c)(221d) A  0° OPEN PARTIALLY PARTIALLY PARTIALLY OPEN OPEN OPEN B  9°OPEN OPEN PARTIALLY PARTIALLY OPEN OPEN C 18° PARTIALLY OPEN PARTIALLYPARTIALLY OPEN OPEN OPEN D 27° PARTIALLY OPEN OPEN PARTIALLY OPEN OPEN E36° PARTIALLY PARTIALLY OPEN PARTIALLY OPEN OPEN OPEN F 45° PARTIALLYPARTIALLY OPEN OPEN OPEN OPEN G 54° PARTIALLY PARTIALLY PARTIALLY OPENOPEN OPEN OPEN H 63° OPEN PARTIALLY PARTIALLY OPEN OPEN OPEN I 74°CLOSED CLOSED CLOSED CLOSED J 81° OPEN OPEN OPEN OPEN

In some embodiments, valve ring 2231″ may include intermediateprojections 2246 positioned between certain adjacent positions in whichrotation of valve ring 2231″ would not otherwise close or partiallyclose the respective manifold orifice 2221 a-d. For example,intermediate projection 2246 a may, as depicted in FIG. 14 , causepartial closing of manifold orifice 2221 a as valve ring 2231″ rotatesbetween position A and position B. In such an embodiment, thearrangement of intermediate projections 2246 and slots 2243″ maypartially close all manifold orifices 2221 a-d at intermediate positionsbetween one or more of positions A-J. For example, intermediateprojections 246 may be positioned to partially close manifold orifice2221 a at intermediate positions between positions J and A and betweenpositions A and B, partially close manifold orifice 2221 b atintermediate positions between B and C and between positions C and D,partially close manifold orifice 2221 c at intermediate positionsbetween D and E and between positions E and F, and partially closemanifold orifice 2221 d at intermediate positions between F and G andbetween positions G and H as valve ring 2231″ rotates between positions,placing each respective manifold orifice 221 a-d in the above describedpartially open position. In some embodiments, with all four manifoldorifices 2221 a-d may cause the same amount of force to be applied toeach steering blade 2103 as described herein above. In some embodiments,valve ring 2231″ may be intentionally rotated to one of the intermediatepositions, defined as between positions A and B, B and C, C and D, D andE, E and F, F and G, G and H, H and I, I and J, or J and A, allowing forsuch a condition to be reached. In some such embodiments, theintermediate positions may be reached by a rotation of 4.5° of valvering 2231″ from any of positions A-J.

In some embodiments, as depicted in FIG. 33 , valve ring 2331 mayinclude slots 2343 and may not include a lip such as lip 2249 asdescribed herein above. In such embodiments, slots 2343 may be arrangedsuch that depending on the rotational position of valve ring 2331, eachof manifold orifices 2221 a-d may be opened, partially opened, orclosed. In some such embodiments, slots 2343 may be arranged about valvering 2331 such that manifold orifices 221 a-d opposite one another arenot open at the same time. In some embodiments, slots 2343 may bearranged such that manifold orifices 2221 a-d may be opened at the sametime. In some embodiments, slots 2343 may be arranged such that at acertain rotational position of valve ring 2331, all manifold orifices2221 a-d may be partially open as depicted in FIG. 33 . For example, insome embodiments, positions of valve ring 2331 may result in the openingand closing of manifold orifices 2221 a-d as outlined in Table 2.

TABLE 4 Ring Valve Positions FIG. 33 Valve Ring Angular Orifice 1Orifice 2 Orifice 3 Orifice 4 Position (221a) (221b) (221c) (221d)    0°PARTIALLY PARTIALLY PARTIALLY PARTIALLY OPEN OPEN OPEN OPEN    5°* OPENCLOSED CLOSED CLOSED   15° OPEN OPEN CLOSED CLOSED   25° CLOSED OPENCLOSED CLOSED   35° CLOSED OPEN OPEN CLOSED   45° CLOSED CLOSED OPENCLOSED   55° CLOSED CLOSED OPEN OPEN   65° CLOSED CLOSED CLOSED OPEN  75° OPEN CLOSED CLOSED OPEN  −5° CLOSED CLOSED CLOSED CLOSED

In some embodiments, downhole steering tool 2100 may transmit data tothe surface or to other downhole tools, including but not limited to anMWD tool, LWD tool, instrumented motor, instrumented turbine,instrumented gear-reduced turbine, instrumented axial oscillation tool,instrumented stick-slip mitigation tool, instrumentedsteady-weight-on-bit tool, instrumented reamer, instrumentedunderreamer, and instrumented drill bit. In some embodiments, forexample and without limitation, a series of pressure pulses may beutilized to transmit communication signals. The pressure pulses may begenerated by the opening and closing of one or more steering ports 2107by solenoids 2115 or ring valve 2215.

In some embodiments, solenoids 2115 may be used to generate pressurepulses by opening and closing one or more solenoids 2115. As an exampleutilizing ring valve 2215, valve ring 2231 may be rotated between afirst position corresponding to a minimum pressure drop, i.e. where allmanifold orifices 2221 a-d are closed, to a position corresponding to ahigher pressure drop, such as where all manifold orifices 2221 a-d areopen. For example, such a transition may be achieved by a rotation ofvalve ring 2231′ or 2231″ between positions I and J as described withrespect to FIGS. 34, 35 . As another example, valve ring 2231 may bemoved between a position in which one manifold orifice 221 a-d and aposition where two are open.

In some embodiments, downhole steering tool 2100 may include a dedicatedport 2109″ as depicted in FIG. 36 having a solenoid 2115′ associatedtherewith or having a manifold orifice 221″ associated therewith tobypass a percentage of the internal mud flow to the annulus through achoke 2301 or orifice 2303 could be used. In such an embodiment,dedicated port 2109″ may be added to generate a stronger pressure pulsethan the steering ports 2107. One having ordinary skill in the art withthe benefit of this disclosure will understand that although shown withsolenoid 2115′, manifold orifice 221″ may be used with a valve ringconsistent with any other embodiment described herein.

In some embodiments, the pressure pulses may be utilized to transmit asignal to the surface or other downhole tools, including but not limitedto an MWD tool, LWD tool, instrumented motor, instrumented turbine,instrumented gear-reduced turbine, instrumented axial oscillation tool,instrumented stick-slip mitigation tool, instrumentedsteady-weight-on-bit tool, instrumented reamer, instrumented underreamerand instrumented drill bit. In some embodiments, the pressure pulses maybe utilized to transmit a binary signal. In some embodiments, thepressure-pulse amplitude, frequency, phase or any combination thereofmay be utilized to transmit a binary signal. In some embodiments,Manchester encoding may be utilized to transmit data to the surface,including but not limited to inclination, azimuth, housinggravity/magnetic toolface, target toolface, actual toolface, housingrotation speed, bit rotation speed, shock/vibration severities,temperatures, pressure, other diagnostic information, received downlinkcommand/signal, downlink command/signal reception confirmation, downholesoftware operation mode/state and other data relating to the operationof one or more downhole tools.

Although described with respect to a slowly rotating housing 2101, onehaving ordinary skill in the art with the benefit of this disclosurewill understand that rotation speed of housing 2101 is not limited tothe above mentioned rotation speeds, The steering direction may becontrolled with any rotation speed. Additionally, the specificarrangements described herein of slots 2243, 2243′ of valve rings 231,2231′, 2331 including any tapers 2244′, 2244″ are exemplary and are notintended to limit the scope of this disclosure. Combinations of thedescribed arrangements as well as other arrangements of slots and valverings may be utilized without deviating from the scope of thisdisclosure.

The methods described herein are configured for downhole implementationvia one or more controllers deployed downhole (e.g., in avertical/directional drilling tool). A suitable controller may include,for example, a programmable processor, such as a microprocessor or amicrocontroller and processor-readable or computer-readable program codeembodying logic. A suitable processor may be utilized, for example, toexecute the method embodiments described above with respect to FIGS.28A-J, and 31A-D as well as the corresponding disclosed mathematicalequations for gravity/magnetic toolface. A suitable controller may alsooptionally include other controllable components, such as sensors (e.g.,a temperature sensor), data storage devices, power supplies, timers, andthe like. The controller may also be disposed to be in electroniccommunication with the other sensors (e.g., to receive the continuousinclination and azimuth measurements). A suitable controller may alsooptionally communicate with other instruments in the drill string, suchas, for example, telemetry systems that communicate with the surface. Asuitable controller may further optionally include volatile ornon-volatile memory or a data storage device.

FIG. 37 depicts on overall view of downhole steering tool 2100 havingone or more drilling dynamics data recorders 200, consistent withcertain embodiments of the present disclosure. As shown in FIG. 37 ,downhole steering tool includes bit box 2020, housing 2101, and uppermandrel 2102. Upper mandrel 2102 may be mechanically connected tomandrel 2012, as described above. Drilling dynamics data recorders 200may be positioned within one or more of bit box slot 2104, housing slot2108, and upper mandrel slot 2210.

The foregoing outlines features of several embodiments so that a personof ordinary skill in the art may better understand the aspects of thepresent disclosure. Such features may be replaced by any one of numerousequivalent alternatives, only some of which are disclosed herein. One ofordinary skill in the art should appreciate that they may readily usethe present disclosure as a basis for designing or modifying otherprocesses and structures for carrying out the same purposes and/orachieving the same advantages of the embodiments introduced herein. Oneof ordinary skill in the art should also realize that such equivalentconstructions do not depart from the spirit and scope of the presentdisclosure and that they may make various changes, substitutions, andalterations herein without departing from the spirit and scope of thepresent disclosure.

1. A method comprising: providing a drilling dynamics data recorder, thedrilling dynamics data recorder positioned within a tool, the tool beinga downhole tool of a bottomhole assembly, the drilling dynamics datarecorder including: a sensor package, the sensor package comprising oneor more drilling dynamics sensors; a memory module, the memory module indata communication with the sensor package; a processor, the processorin data communication with the one or more drilling dynamics sensors;and an electrical energy source, a communication port, the communicationport in data communication with the memory module or an external devicevia a common communication bus; the electrical energy source inelectrical communication with the memory module, the sensor package, andthe processor; taking measurements using the drilling dynamics sensors,the measurements comprising pseudo formation-evaluation parameters;transmitting the measurements from the drilling dynamics sensors to theexternal device using the communication port; and transmitting thepseudo formation-evaluation parameters to a surface location via ameasurement-while-drilling (MWD) tool.
 2. The method of claim 1 furthercomprising generating a pseudo formation-evaluation log from themeasurements from the drilling dynamics sensors in combination withsurface parameters.
 3. The method of claim 1 further comprisingrecording pseudo formation-evaluation parameters in the memory module.4. The method of claim 1, further comprising using the pseudoformation-evaluation parameters for post run analysis, real-timeanalysis, or a combination thereof.
 5. The method of claim 1, furthercomprising using the drilling dynamics data for determination ofinclination, total gravity field, radial acceleration, tangentialacceleration, rotation speed (angular velocity), tension, compression,torque on bit, weight on bit, bending moment, bending toolface, orpressure.
 6. The method of claim 1, wherein the downhole tool comprises:a drill bit; a stabilizer; a motor; a gear-reduced turbine; a rotarysteerable tool; a measurement-while-drilling tool; a BHA; a drill bit; astabilizer; a cross-over; a drill pipe; a drill collar; a pin-boxconnection; a jar; a reamer; an underreamer; a friction reducing tool; astring stabilizer; a near-bit stabilizer; a mud motor; a turbine; and astick-slip mitigation tool; wherein the mud motor has a top sub, a rotorcatch, a rotor, a transmission, and a bit box; and wherein the rotarysteerable tool has a top sub, a mandrel, and a slowly rotating housing.7. The downhole tool of claim 6, wherein the drilling dynamics datarecorder is positioned within the drill bit; the stabilizer; the agear-reduced turbine; the measurement-while-drilling tool; the BHA; thedrill bit; the stabilizer; the cross-over; the drill pipe; the drillcollar; the pin-box connection; the jar; the reamer; the underreamer;the friction reducing tool; the string stabilizer; the near-bitstabilizer; the turbine; the stick-slip mitigation tool.
 8. The methodof claim 1, wherein the electrical energy source is a rechargeablebattery or a non-rechargeable battery.
 9. The method of claim 1, whereinthe one or more drilling dynamics sensors are digital, solid-statesensors.
 10. A method comprising: providing a drilling dynamics datarecorder, the drilling dynamics data recorder positioned within a tool,the tool being a downhole tool of a bottomhole assembly, the drillingdynamics data recorder including: a sensor package, the sensor packagecomprising one or more drilling dynamics sensors; a memory module, thememory module in data communication with the sensor package; aprocessor, the processor in data communication with the one or moredrilling dynamics sensors; an electrical energy source; and acommunication port, the communication port in data communication withthe memory module or an external device via a common communication bus;wherein the electrical energy source is in electrical communication withthe memory module, the sensor package, and the processor; takingmeasurements using the drilling dynamics sensors, the measurementscomprising rock mechanics-analysis parameters; transmitting themeasurements from the drilling dynamics sensors to the external deviceusing the communication port; and transmitting therock-mechanics-analysis parameters to a surface location via ameasurement-while-drilling (MWD) tool.
 11. The method of claim 10further comprising performing a rock mechanics analysis using the rockmechanics-analysis parameters.
 12. The method of claim 11, wherein therock mechanics analysis includes the analysis/identification offractures, fracture directions, rock confined/unconfined compressivestrength, Young's modulus of elasticity, or Poisson's ratio.
 13. Themethod of claim 11, wherein the rock mechanics analysis may be performedby combining the rock mechanics analysis parameters with surfacemeasured parameters, such as WOB (weight on bit), TOB (torque on bit),RPM (revolutions per minute), ROP (rate of penetration), and flow rate.14. The method of claim 10, further comprising using the drillingdynamics data for post run analysis, real-time analysis, or acombination thereof.
 15. The method of claim 10, further comprisingusing the drilling dynamics data for post run evaluation of drillingdynamics, frequency spectrum, statistical analysis, condition-basedmonitoring/maintenance (CBM), or a combination thereof.
 16. The methodof claim 10 further comprising recording the drilling dynamics data inburst mode or continuous mode.
 17. The method of claim 10, furthercomprising using the drilling dynamics data for determination ofinclination, total gravity field, radial acceleration, tangentialacceleration, rotation speed (angular velocity), tension, compression,torque on bit, weight on bit, bending moment, bending toolface, orpressure.
 18. The method of claim 10, wherein the tool comprises: adrill bit; a stabilizer; a motor; a gear-reduced turbine; a rotarysteerable tool; a measurement-while-drilling tool; a BHA; a drill bit; astabilizer; a cross-over; a drill pipe; a drill collar; a pin-boxconnection; a jar; a reamer; an underreamer; a friction reducing tool; astring stabilizer; a near-bit stabilizer; a mud motor; a turbine; and astick-slip mitigation tool; wherein the mud motor has a top sub, a rotorcatch, a rotor, a transmission, and a bit box; and wherein the rotarysteerable tool has a top sub, a mandrel, and a slowly rotating housing.19. The method of claim 18, wherein the drilling dynamics data recorderis positioned within the drill bit; the stabilizer; the a gear-reducedturbine; the measurement-while-drilling tool; the BHA; the drill bit;the stabilizer; the cross-over; the drill pipe; the drill collar; thepin-box connection; the jar; the reamer; the underreamer; the frictionreducing tool; the string stabilizer; the near-bit stabilizer; theturbine; the stick-slip mitigation tool; the top sub; the rotor catch;the rotor; the transmission; the bit box; the top sub; the mandrel; orthe slowly rotating housing.
 20. The method of claim 10, wherein theelectrical energy source is a rechargeable battery or a non-rechargeablebattery.